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Principles of Consolidation and Accounting for Investments

The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses. Amounts representing the Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are included in “Investments, advances and long-term receivables”. The Corporation’s share of the net income of these companies is included in the Consolidated Statement of Income caption “Income from equity affiliates”.

Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and management compensation and succession plans.

Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value that is other than temporary. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.

Investments in equity securities other than consolidated subsidiaries and equity method investments are measured at fair value with changes in fair value recognized in net income. The Corporation uses the modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions in a similar investment of the same issuer.

The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in “Accumulated other comprehensive income”.

Revenue Recognition

The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments to reflect market conditions. Revenue is recognized at the amount the Corporation expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when the price is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility.

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold.

“Sales and other operating revenue” and “Notes and accounts receivable” primarily arise from contracts with customers. Long-term receivables are primarily from non-customers. Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments and accruals of expected volume discounts and are not significant.

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Income and Other Taxes

The Corporation excludes from the Consolidated Statement of Income certain sales and value-added taxes imposed on and concurrent with revenue-producing transactions with customers and collected on behalf of governmental authorities. Similar taxes, for which the Corporation is not considered to be an agent for the government, are reported on a gross basis (included in both “Sales and other operating revenue” and “Other taxes and duties”).

The Corporation accounts for U.S. tax on global intangible low-taxed income as an income tax expense in the period in which it is incurred.

Derivative Instruments

The Corporation may use derivative instruments for trading purposes and to offset exposures associated with commodity prices, foreign currency exchange rates and interest rates that arise from existing assets, liabilities, firm commitments and forecasted transactions. All derivative instruments, except those designated as normal purchase and normal sale, are recorded at fair value. Derivative assets and liabilities with the same counterparty are netted if the right of offset exists and certain other criteria are met. Collateral payables or receivables are netted against derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from adjusting a derivative to fair value depends on the purpose for the derivative. All gains and losses from derivative instruments for which the Corporation does not apply hedge accounting are immediately recognized in earnings. The Corporation may designate derivatives as fair value or cash flow hedges. For fair value hedges, the gain or loss from derivative instruments and the offsetting gain or loss from the hedged item are recognized in earnings. For cash flow hedges, the gain or loss from the derivative instrument is initially reported as a component of other comprehensive income and subsequently reclassified into earnings in the period that the forecasted transaction affects earnings.

Fair Value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

Inventories

Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.

Property, Plant and Equipment

Cost Basis. The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.

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To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes.

Investments in refinery, chemical process, and lubes basestock manufacturing equipment are generally depreciated on a straight-line basis over a 25-year life. Service station buildings and fixed improvements generally are depreciated over a 20-year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

Impairment Assessment. The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:

• a significant decrease in the market price of a long-lived asset;

• a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;

• a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;

• an accumulation of project costs significantly in excess of the amount originally expected;

• a current-period operating loss combined with a history and forecast of operating or cash flow losses; and

• a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

Asset valuation analysis, profitability reviews and other periodic control processes assist the Corporation in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable.

In general, the Corporation does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments and technology and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities and levels of prosperity. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and development and production costs. During the lifespan of these major assets, the Corporation expects that oil and gas prices will experience significant volatility, and consequently these assets will experience periods of higher earnings and periods of lower earnings, or even losses.

In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are subject to wide fluctuations, longer-term price views are more stable and meaningful for purposes of assessing future cash flows.

When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the Corporation’s price or margin assumptions it uses for its capital investment decisions. To the extent those changes result in a significant reduction to its oil price, natural gas price or margin ranges, the Corporation may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, an indicator of potential impairment for certain assets.

In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on Oil and Gas Exploration and Production Activities is required to use prices based on the average of first-of-month prices. These prices represent discrete points in time and could be higher or lower than the Corporation’s price assumptions which are used for impairment assessments. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment.

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The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies in part on the Corporation’s planning and budgeting cycle. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the Corporation’s assumptions which are developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

An asset group is impaired if its estimated undiscounted cash flows are less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Fair value is based on market prices if an active market exists for the asset group, or discounted cash flows using a discount rate commensurate with the risk.

Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the Corporation's future development plans, the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

Other. Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any interest retained nor any substantial obligation for future performance by the Corporation. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life of the related assets.

Environmental Liabilities

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties, and projected cash expenditures are not discounted.

Foreign Currency Translation

The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates.

Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom and continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets.

For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.

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Effective January 1, 2020, the Corporation adopted the Financial Accounting Standards Board’s update, Financial Instruments – Credit Losses (Topic 326) , as amended. The standard requires a valuation allowance for credit losses be recognized for certain financial assets that reflects the current expected credit loss over the asset’s contractual life. The valuation allowance considers the risk of loss, even if remote, and considers past events, current conditions and reasonable and supportable forecasts. The standard requires this expected loss methodology for trade receivables, certain other financial assets and off-balance sheet credit exposures. The cumulative effect adjustment related to the adoption of this standard reduced ExxonMobil's share of equity by $ 93 million.

The Corporation is exposed to credit losses primarily through sales of petroleum products, crude oil, natural gas liquids and natural gas, as well as loans to equity companies and joint venture receivables. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or the Corporation’s assessment of the counterparty’s credit worthiness, contract terms, country of operation, and other risks. The Corporation can require prepayment or collateral to mitigate certain credit risks.

The Corporation groups financial assets into portfolios that share similar risk characteristics for purposes of determining the allowance for credit losses and assesses if a significant change in the risk of credit loss has occurred. Among the quantitative and qualitative factors considered are historical financial data, current conditions, industry and country risk, current credit ratings and the quality of third-party guarantees secured from the counterparty. Financial assets are written off in whole, or in part, when practical recovery efforts have been exhausted and no reasonable expectation of recovery exists. Subsequent recoveries of amounts previously written off are recognized in earnings. The Corporation manages receivable portfolios using past due balances as a key credit quality indicator.

The Corporation recognizes a credit allowance for off-balance sheet credit exposures as a liability on the balance sheet, separate from the allowance for credit losses related to recognized financial assets. Among these exposures are unfunded loans to equity companies and financial guarantees that cannot be cancelled unilaterally by the Corporation.

			Allowance for Current Expected Credit Losses
			Notes and Accounts Receivable												Advances and Long-Term Receivables						Liabilities for Off- Balance Sheet Assets
			Trade						Other																		Total
			(millions of dollars)
Balance at December 31, 2019			34						56						413						—						503
Cumulative effect of accounting change			52						6						39						12						109
Current period provision			9						15						( 9 )						( 1 )						14
Write-offs charged against the allowance			( 2 )						( 3 )						—						—						( 5 )
Other			2						( 3 )						3						—						2
Balance at December 31, 2020			95						71						446						11						623
Balance at December 31, 2020
Financial Assets subject to credit losses standard - net			16,250						1,962						9,447

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Research and development expenses totaled $ 1,016 million in 2020, $ 1,214 million in 2019, and $ 1,116 million in 2018.

Net income included before-tax aggregate foreign exchange transaction losses of $ 24 million, $ 104 million and $ 138 million in 2020, 2019 and 2018, respectively.

In 2020, 2019, and 2018, net income included gains of $ 41 million, $ 523 million, and $ 107 million, respectively, attributable to the combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $ 5.4 billion and $ 9.7 billion at December 31, 2020, and 2019, respectively.

Crude oil, products and merchandise as of year-end 2020 and 2019 consist of the following:

			Dec 31, 2020						Dec 31, 2019
			(millions of dollars)
Crude oil			5,354						5,111
Petroleum products			5,138						5,281
Chemical products			3,023						3,240
Gas/other			654						378
Total			14,169						14,010

Mainly as a result of declines in prices for crude oil, natural gas and petroleum products in 2020 and a significant decline in its market capitalization at the end of the first quarter, the Corporation recognized before-tax goodwill impairment charges of $ 611 million in Upstream, Downstream, and Chemical reporting units. Fair value of the goodwill reporting units primarily reflected market-based estimates of historical EBITDA multiples at the end of the first quarter. Charges related to goodwill impairments are included in “Depreciation and depletion” on the Statement of Income.

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ExxonMobil Share of Accumulated Other Comprehensive Income			Cumulative Foreign Exchange Translation Adjustment						Postretirement Benefits Reserves Adjustment						Total
			(millions of dollars)
Balance as of December 31, 2017			( 9,482 )						( 6,780 )						( 16,262 )
Current period change excluding amounts reclassified from accumulated other comprehensive income			( 4,595 )						201						( 4,394 )
Amounts reclassified from accumulated other comprehensive income			196						896						1,092
Total change in accumulated other comprehensive income			( 4,399 )						1,097						( 3,302 )
Balance as of December 31, 2018			( 13,881 )						( 5,683 )						( 19,564 )
Current period change excluding amounts reclassified from accumulated other comprehensive income			1,435						( 1,927 )						( 492 )
Amounts reclassified from accumulated other comprehensive income			—						563						563
Total change in accumulated other comprehensive income			1,435						( 1,364 )						71
Balance as of December 31, 2019			( 12,446 )						( 7,047 )						( 19,493 )
Current period change excluding amounts reclassified from accumulated other comprehensive income (1)			1,818						95						1,913
Amounts reclassified from accumulated other comprehensive income			14						861						875
Total change in accumulated other comprehensive income			1,832						956						2,788
Balance as of December 31, 2020			( 10,614 )						( 6,091 )						( 16,705 )

(1) Cumulative Foreign Exchange Translation Adjustment includes net investment hedge gain/(loss) of $( 355 ) million, net of taxes.

Amounts Reclassified Out of Accumulated Other Comprehensive Income - Before-tax Income/(Expense)			2020						2019						2018
			(millions of dollars)
Foreign exchange translation gain/(loss) included in net income (Statement of Income line: Other income)			( 14 )						—						( 196 )
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs (Statement of Income line: Non-service pension and postretirement benefit expense)			( 1,158 )						( 751 )						( 1,208 )

Income Tax (Expense)/Credit For Components of Other Comprehensive Income			2020						2019						2018
			(millions of dollars)
Foreign exchange translation adjustment			118						88						32
Postretirement benefits reserves adjustment (excluding amortization)			109						719						( 193 )
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs			( 262 )						( 169 )						( 277 )
Total			( 35 )						638						( 438 )

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The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.

For 2020, the “Depreciation and depletion” and “Deferred income tax charges/(credits)” on the Consolidated Statement of Cash Flows includes impacts from asset impairments, primarily in Upstream.

For 2019, the “Net (gain)/loss on asset sales” on the Consolidated Statement of Cash Flows includes before-tax amounts from the sale of non-operated upstream assets in Norway and upstream asset transactions in the U.S. The Norway assets were sold for $ 4.5 billion, resulting in a gain of $ 3.7 billion and cash proceeds of $ 3.1 billion in 2019. For 2018, the number includes before-tax amounts from the sale of service stations in Germany, the divestment of the Augusta refinery in Italy, and the sale of an undeveloped upstream property in Australia. These net gains are reported in “Other income” on the Consolidated Statement of Income.

In 2020, the “Additions/(reductions) in commercial paper, and debt with three months or less maturity” on the Consolidated Statement of Cash Flows includes a net $ 8.4 billion addition of commercial paper with maturity over three months. The gross amount issued was $ 35.4 billion, while the gross amount repaid was $ 27.0 billion. In 2019, the number includes a net $ 4.6 billion addition of commercial paper with maturity over three months. The gross amount issued was $ 18.9 billion, while the gross amount repaid was $ 14.3 billion. In 2018, the number includes a net $ 275 million addition of commercial paper with maturity over three months. The gross amount issued was $ 4.0 billion, while the gross amount repaid was $ 3.8 billion.

			2020						2019						2018
			(millions of dollars)
Income taxes paid			2,428						7,018						9,294
Cash interest paid
Included in cash flows from operating activities			786						560						303
Capitalized, included in cash flows from investing activities			665						731						652
Total cash interest paid			1,451						1,291						955

															Dec 31, 2020						Dec 31, 2019
															(millions of dollars)
Notes and accounts receivable
Trade, less reserves of $ 96 million and $ 34 million															16,339						21,100
Other, less reserves of $ 378 million and $ 371 million															4,242						5,866
Total															20,581						26,966
Notes and loans payable
Bank loans															222						316
Commercial paper															17,306						18,561
Long-term debt due within one year															2,930						1,701
Total															20,458						20,578
Accounts payable and accrued liabilities
Trade payables															17,499						24,694
Payables to equity companies															6,476						6,825
Accrued taxes other than income taxes															3,408						3,301
Other															7,838						7,011
Total															35,221						41,831

The Corporation has short-term committed lines of credit of $ 11.3 billion which were unused as of December 31, 2020. These lines are available for general corporate purposes.

The weighted-average interest rate on short-term borrowings outstanding was 0.2 percent and 1.7 percent at December 31, 2020, and 2019, respectively.

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The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1). These companies are primarily engaged in oil and gas exploration and production, and natural gas marketing in North America; natural gas exploration, production and distribution in Europe; liquefied natural gas (LNG) operations and transportation of crude oil in Africa; and exploration, production, LNG operations, and the manufacture and sale of petroleum and petrochemical products in Asia and the Middle East. Also included are several refining, petrochemical manufacturing and marketing ventures.

The share of total equity company revenues from sales to ExxonMobil consolidated companies was 11 percent, 13 percent and 14 percent in the years 2020, 2019 and 2018, respectively.

The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the factors giving rise to the difference. The amortization of this difference, as appropriate, is included in “Income from equity affiliates” on the Consolidated Statement of Income.

Impairments related to U.S. upstream equity investments of $ 600 million are included in “Income from equity affiliates” on the Consolidated Statement of Income.

			2020												2019												2018
Equity Company Financial Summary			Total						ExxonMobil Share						Total						ExxonMobil Share						Total						ExxonMobil Share
			(millions of dollars)
Total revenues			69,954						21,282						102,365						31,240						112,938						34,539
Income before income taxes			12,743						2,830						29,424						7,927						37,203						10,482
Income taxes			4,333						870						9,725						2,500						11,568						3,151
Income from equity affiliates			8,410						1,960						19,699						5,427						25,635						7,331
Current assets			33,419						11,969						36,035						12,661						38,670						13,394
Long-term assets			150,358						41,457						143,321						40,001						128,830						35,970
Total assets			183,777						53,426						179,356						52,662						167,500						49,364
Current liabilities			18,827						5,245						24,583						6,939						27,324						7,606
Long-term liabilities			66,053						19,927						61,022						18,158						56,913						17,109
Net assets			98,897						28,254						93,751						27,565						83,263						24,649

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A list of significant equity companies as of December 31, 2020, together with the Corporation’s percentage ownership interest, is detailed below:

			Percentage Ownership Interest
Upstream
Aera Energy LLC			48
Barzan Gas Company Limited			7
BEB Erdgas und Erdoel GmbH & Co. KG			50
Cameroon Oil Transportation Company S.A.			41
Caspian Pipeline Consortium - Kazakhstan			8
CORAL FLNG, S.A.			25
Cross Timbers Energy, LLC			50
Golden Pass LNG Terminal LLC			30
Golden Pass Pipeline LLC			30
Marine Well Containment Company LLC			10
Mozambique Rovuma Venture, S.p.A.			36
Nederlandse Aardolie Maatschappij B.V.			50
Papua New Guinea Liquefied Natural Gas Global Company LDC			33
Permian Highway Pipeline LLC			20
Qatar Liquefied Gas Company Limited			10
Qatar Liquefied Gas Company Limited (2)			24
Ras Laffan Liquefied Natural Gas Company Limited			25
Ras Laffan Liquefied Natural Gas Company Limited (II)			31
Ras Laffan Liquefied Natural Gas Company Limited (3)			30
South Hook LNG Terminal Company Limited			24
Tengizchevroil, LLP			25
Terminale GNL Adriatico S.r.l.			71
Downstream
Alberta Products Pipe Line Ltd.			45
Fujian Refining & Petrochemical Co. Ltd.			25
Permian Express Partners LLC			12
Saudi Aramco Mobil Refinery Company Ltd.			50
Chemical
Al-Jubail Petrochemical Company			50
Gulf Coast Growth Ventures LLC			50
Saudi Yanbu Petrochemical Co.			50

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			December 31, 2020												December 31, 2019
Property, Plant and Equipment			Cost						Net						Cost						Net
			(millions of dollars)
Upstream			386,614						167,472						376,041						196,767
Downstream			57,922						27,716						52,527						24,506
Chemical			42,868						21,924						40,788						21,260
Other			17,918						10,441						17,346						10,485
Total			505,322						227,553						486,702						253,018

The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932, and relies in part on the Corporation’s planning and budgeting cycle. In 2020, the Corporation identified a number of situations where events or changes in circumstances indicated that the carrying value of certain long-lived assets may not be recoverable. Those situations primarily related to the annual review and approval of the Corporation's business and strategic plan. As part of the planning process, the Corporation assessed its full portfolio to prioritize assets with the highest future value potential within its broad range of available opportunities in order to optimize resources within current levels of debt and operating cash flow, as well as identify potential asset divestment candidates. This effort included a re-assessment of dry gas assets, primarily in North America, which previously had been included in the Corporation’s future development plans. Under the plan as approved, the Corporation no longer plans to develop a significant portion of its dry gas portfolio, including a portion of its resources in the Appalachian, Rocky Mountains, Oklahoma, Texas, Louisiana, and Arkansas regions of the U.S., as well as resources in Western Canada and Argentina. The decision not to develop these assets resulted in non-cash, before-tax charges of $ 24.4 billion in Upstream to reduce the carrying value of those assets to fair value. Other before-tax impairment charges in 2020 included $ 0.9 billion in Upstream, $ 0.5 billion in Downstream, and $ 0.1 billion in Chemical. Impairment charges are primarily recognized in the lines “Depreciation and depletion” and “Exploration expenses, including dry holes” on the Consolidated Statement of Income.

The assessment of fair value requires the use of Level 3 inputs and assumptions that are based upon the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, commodity prices which were consistent with the average of third-party industry experts and government agencies, drilling and development costs, and discount rates ranging from 6 percent to 8 percent which are reflective of the characteristics of the asset group.

Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s price outlooks, changes in the allocation of capital, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price increases. However, due to the inherent difficulty in predicting future commodity prices, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets. In 2019 and 2018, the before-tax impairment charges were $ 0.1 billion and $ 0.7 billion, respectively.

Accumulated depreciation and depletion totaled $ 277,769 million at the end of 2020 and $ 233,684 million at the end of 2019. Interest capitalized in 2020, 2019 and 2018 was $ 665 million, $ 731 million and $ 652 million, respectively.

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Asset Retirement Obligations

The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value.

Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations.

The following table summarizes the activity in the liability for asset retirement obligations:

			2020						2019						2018
			(millions of dollars)
Balance at January 1			11,280						12,103						12,705
Accretion expense and other provisions			584						649						681
Reduction due to property sales			( 77 )						( 1,085 )						( 333 )
Payments made			( 669 )						( 827 )						( 600 )
Liabilities incurred			26						89						46
Foreign currency translation			239						84						( 481 )
Revisions			( 136 )						267						85
Balance at December 31			11,247						11,280						12,103

The long-term Asset Retirement Obligations were $ 10,558 million and $ 10,279 million at December 31, 2020, and 2019, respectively, and are included in “Other long-term obligations.”

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The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

The following two tables provide details of the changes in the balance of suspended exploratory well costs as well as an aging summary of those costs.

Change in capitalized suspended exploratory well costs:

			2020						2019						2018
			(millions of dollars)
Balance beginning at January 1			4,613						4,160						3,700
Additions pending the determination of proved reserves			208						532						564
Charged to expense			( 318 )						( 46 )						( 7 )
Reclassifications to wells, facilities and equipment based on the determination of proved reserves			( 174 )						( 37 )						( 48 )
Divestments/Other			53						4						( 49 )
Ending balance at December 31			4,382						4,613						4,160
Ending balance attributed to equity companies included above			306						306						306

Period end capitalized suspended exploratory well costs:

			2020						2019						2018
			(millions of dollars)
Capitalized for a period of one year or less			208						532						564
Capitalized for a period of between one and five years			1,828						2,206						2,028
Capitalized for a period of between five and ten years			1,932						1,411						1,150
Capitalized for a period of greater than ten years			414						464						418
Capitalized for a period greater than one year - subtotal			4,174						4,081						3,596
Total			4,382						4,613						4,160

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a breakdown of the number of projects with only exploratory well costs capitalized for a period of one year or less and those that have had exploratory well costs capitalized for a period greater than one year.

			2020						2019						2018
Number of projects that only have exploratory well costs capitalized for a period of one year or less			3						4						6
Number of projects that have exploratory well costs capitalized for a period greater than one year			34						46						52
Total			37						50						58

Of the 34 projects that have exploratory well costs capitalized for a period greater than one year as of December 31, 2020, 13 projects have drilling in the preceding year or exploratory activity planned in the next two years, while the remaining 21 projects are those with completed exploratory activity progressing toward development.

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The table below provides additional detail for those 21 projects, which total $ 3,181 million.

Country/Project			Dec. 31, 2020			Years Wells Drilled / Acquired									Comment
(millions of dollars)
Angola
– Kaombo Split Hub Phase 2			10			2006									Evaluating development plan to tie into planned production facilities.
Argentina
– La Invernada			72			2014									Evaluating development plan to tie into planned infrastructure.
Australia
– Gorgon Area Ullage			347			1994			-			2015			Evaluating development plans to tie into existing LNG facilities.
Brazil
– Bacalhau Phase 1			284			2018									Continuing discussions with the government regarding development plan.
Canada
– Hibernia North			26			2019									Awaiting capacity in existing/planned infrastructure.
Iraq
– Kurdistan Pirmam			109			2015									Evaluating commercialization alternatives, while waiting for government approval to enter Gas Holding Period.
Kazakhstan
– Kairan			53			2004			-			2007			Evaluating commercialization and field development alternatives, while continuing discussions with the government regarding the development plan.
Mozambique
– Rovuma LNG Future Non-Straddling Train			120			2017									Evaluating/progressing development plan to tie into planned LNG facilities.
– Rovuma LNG Phase 1			150			2017									Progressing development plan to tie into planned LNG facilities.
– Rovuma LNG Unitized Trains			35			2017									Evaluating/progressing development plan to tie into planned LNG facilities.
Nigeria
– Bonga North			34			2004			-			2009			Evaluating/progressing development plan for tieback to existing/planned infrastructure.
– Bonga SW			3			2001									Evaluating/progressing development plan for tieback to existing/planned infrastructure.
– Bosi			79			2002			-			2006			Development activity under way, while continuing discussions with the government regarding development plan.
– Owowo			67			2009			-			2016			Evaluating development plan for tieback to existing production facilities.
– Pegi			32			2009									Awaiting capacity in existing/planned infrastructure.
– Ukot SW			41			2014									Evaluating development plan for tieback to existing production facilities.
Papua New Guinea
– Papua LNG			246			2017									Evaluating/progressing development plans.
– P'nyang			116			2012			-			2018			Evaluating/progressing development plans.
Romania
– Neptun Deep			536			2012			-			2016			Continuing discussions with the government regarding development plan.
Tanzania
– Tanzania Block 2			525			2012			-			2015			Evaluating development alternatives, while continuing discussions with the government regarding development plan.
Vietnam
– Blue Whale			296			2011			-			2015			Evaluating/progressing development plans.
Total 2020 (21 projects)			3,181

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The Corporation and its consolidated affiliates generally purchase the property, plant and equipment used in operations, but there are situations where assets are leased, primarily for drilling equipment, tankers, office buildings, railcars, and other moveable equipment. Right of use assets and lease liabilities are established on the balance sheet for leases with an expected term greater than one year by discounting the amounts fixed in the lease agreement for the duration of the lease which is reasonably certain, considering the probability of exercising any early termination and extension options. The portion of the fixed payment related to service costs for drilling equipment, tankers and finance leases is excluded from the calculation of right of use assets and lease liabilities. Generally, assets are leased only for a portion of their useful lives, and are accounted for as operating leases. In limited situations assets are leased for nearly all of their useful lives, and are accounted for as finance leases.

Variable payments under these lease agreements are not significant. Residual value guarantees, restrictions, or covenants related to leases, and transactions with related parties are also not significant. In general, leases are capitalized using the incremental borrowing rate of the leasing affiliate. The Corporation’s activities as a lessor are not significant.

			Operating Leases
			Drilling Rigs and Related Equipment						Other						Total						Finance Leases
			(millions of dollars)
Lease Cost			2020
Operating lease cost			297						1,256						1,553
Short-term and other (net of sublease rental income)			530						1,083						1,613
Amortization of right of use assets																					143
Interest on lease liabilities																					169
Total			827						2,339						3,166						312

			Operating Leases
			Drilling Rigs and Related Equipment						Other						Total						Finance Leases
			(millions of dollars)
Lease Cost			2019
Operating lease cost			238						1,196						1,434
Short-term and other (net of sublease rental income)			926						1,116						2,042
Amortization of right of use assets																					121
Interest on lease liabilities																					133
Total			1,164						2,312						3,476						254

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			Operating Leases
			Drilling Rigs and Related Equipment						Other						Total						Finance Leases
			(millions of dollars)
Balance Sheet			December 31, 2020
Right of use assets
Included in Other assets, including intangibles - net			834						5,244						6,078
Included in Property, plant and equipment - net																					2,188
Total right of use assets			834						5,244						6,078						2,188
Lease liability due within one year
Included in Accounts payable and accrued liabilities			243						925						1,168						4
Included in Notes and loans payable																					102
Long-term lease liability
Included in Other long-term obligations			589						3,405						3,994
Included in Long-term debt																					1,680
Included in Long-term obligations to equity companies																					135
Total lease liability			832						4,330						5,162						1,921
Weighted average remaining lease term - years			5						12						11						20
Weighted average discount rate - percent			2.2		%				3.0		%				2.9		%				8.9		%

			Operating Leases
			Drilling Rigs and Related Equipment						Other						Total						Finance Leases
			(millions of dollars)
Balance Sheet			December 31, 2019
Right of use assets
Included in Other assets, including intangibles - net			572						6,061						6,633
Included in Property, plant and equipment - net																					1,997
Total right of use assets			572						6,061						6,633						1,997
Lease liability due within one year
Included in Accounts payable and accrued liabilities			221						990						1,211						15
Included in Notes and loans payable																					84
Long-term lease liability
Included in Other long-term obligations			330						4,152						4,482
Included in Long-term debt																					1,670
Included in Long-term obligations to equity companies																					139
Total lease liability			551						5,142						5,693						1,908
Weighted average remaining lease term - years			4						11						10						20
Weighted average discount rate - percent			3.1		%				3.2		%				3.2		%				9.7		%

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			Operating Leases
			Drilling Rigs and Related Equipment						Other						Total						Finance Leases
			(millions of dollars)
Maturity Analysis of Lease Liabilities			December 31, 2020
2021			259						1,031						1,290						268
2022			256						817						1,073						259
2023			97						482						579						252
2024			71						387						458						247
2025			71						342						413						240
2026 and beyond			124						2,157						2,281						2,544
Total lease payments			878						5,216						6,094						3,810
Discount to present value			( 46 )						( 886 )						( 932 )						( 1,889 )
Total lease liability			832						4,330						5,162						1,921

In addition to the lease liabilities in the table immediately above, at December 31, 2020, undiscounted commitments for leases not yet commenced totaled $ 445 million for operating leases and $ 4,109 million for finance leases. The finance leases relate to floating production storage and offloading vessels, LNG transportation vessels, and a long-term hydrogen purchase agreement. The underlying assets for these finance leases were primarily designed by, and are being constructed by, the lessors.

			Operating Leases
			Drilling Rigs and Related Equipment						Other						Total						Finance Leases
			(millions of dollars)
Other Information			2020
Cash paid for amounts included in the measurement of lease liabilities
Cash flows from operating activities									1,159						1,159						31
Cash flows from investing activities			283												283
Cash flows from financing activities																					94
Noncash right of use assets recorded in exchange for lease liabilities			552						183						735						108

			Operating Leases
			Drilling Rigs and Related Equipment						Other						Total						Finance Leases
			(millions of dollars)
Other Information			2019
Cash paid for amounts included in the measurement of lease liabilities
Cash flows from operating activities									1,116						1,116						54
Cash flows from investing activities			258												258
Cash flows from financing activities																					177
Noncash right of use assets recorded for lease liabilities
For January 1 adoption of ASC 842			445						2,818						3,263
In exchange for lease liabilities during the period			350						3,313						3,663						422

Disclosures under the previous lease standard (ASC 840)

Net rental cost incurred under both cancelable and noncancelable operating leases was $ 2,715 million in 2018.

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Earnings per common share			2020						2019						2018
Net income (loss) attributable to ExxonMobil (millions of dollars)			( 22,440 )						14,340						20,840
Weighted average number of common shares outstanding (millions of shares)			4,271						4,270						4,270
Earnings (Loss) per common share (dollars) (1)			( 5.25 )						3.36						4.88
Dividends paid per common share (dollars)			3.48						3.43						3.23

(1) The earnings (loss) per common share and earnings (loss) per common share - assuming dilution are the same in each period shown.

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Financial Instruments. The estimated fair value of financial instruments at December 31, 2020 and December 31, 2019, and the related hierarchy level for the fair value measurement is as follows:

			At December 31, 2020
			(millions of dollars)
			Fair Value
			Level 1						Level 2						Level 3						Total Gross Assets & Liabilities						Effect of Counterparty Netting						Effect of Collateral Netting						Difference in Carrying Value and Fair Value						Net Carrying Value
Assets
Derivative assets (1)			1,247						194						—						1,441						( 1,282 )						( 6 )						—						153
Advances to/receivables from equity companies (2)(6)			—						3,275						5,904						9,179						—						—						( 367 )						8,812
Other long-term financial assets (3)			1,235						—						944						2,179						—						—						125						2,304
Liabilities
Derivative liabilities (4)			1,443						254						—						1,697						( 1,282 )						( 202 )						—						213
Long-term debt (5)			50,263						125						4						50,392						—						—						( 4,890 )						45,502
Long-term obligations to equity companies (6)			—						—						3,530						3,530						—						—						( 277 )						3,253
Other long-term financial liabilities (7)			—						—						964						964						—						—						44						1,008

			At December 31, 2019
			(millions of dollars)
			Fair Value
			Level 1						Level 2						Level 3						Total Gross Assets & Liabilities						Effect of Counterparty Netting						Effect of Collateral Netting						Difference in Carrying Value and Fair Value						Net Carrying Value
Assets
Derivative assets (1)			533						102						—						635						( 463 )						( 70 )						—						102
Advances to/receivables from equity companies (2)(6)			—						1,941						6,729						8,670						—						—						( 128 )						8,542
Other long-term financial assets (3)			1,145						—						974						2,119						—						—						44						2,163
Liabilities
Derivative liabilities (4)			568						70						—						638						( 463 )						( 105 )						—						70
Long-term debt (5)			25,652						134						3						25,789						—						—						( 1,117 )						24,672
Long-term obligations to equity companies (6)			—						—						4,245						4,245						—						—						( 257 )						3,988
Other long-term financial liabilities (7)			—						—						1,042						1,042						—						—						16						1,058

(1) Included in the Balance Sheet lines: Notes and accounts receivable - net and Other assets, including intangibles - net

(2) Included in the Balance Sheet line: Investments, advances and long-term receivables

(3) Included in the Balance Sheet lines: Investments, advances and long term receivables and Other assets, including intangibles - net

(4) Included in the Balance Sheet lines: Accounts payable and accrued liabilities and Other long-term obligations

(5) Excluding finance lease obligations

(6) Advances to/receivables from equity companies and long-term obligations to equity companies are mainly designated as hierarchy level 3 inputs. The fair value is calculated by discounting the remaining obligations by a rate consistent with the credit quality and industry of the company.

(7) Included in the Balance Sheet line: Other long-term obligations. Includes contingent consideration related to a prior year acquisition where fair value is based on expected drilling activities and discount rates.

The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $ 23 billion of long-term debt during 2020.

At December 31, 2020 and December 31, 2019, the Corporation had $ 504 million and $ 379 million of collateral under master netting arrangements not offset against the derivatives on the Consolidated Balance Sheet, primarily related to initial margin requirements.

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Derivative Instruments. The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in commodity prices, currency rates and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and for trading purposes. Commodity contracts held for trading purposes are presented in the Consolidated Statement of Income on a net basis in the line “Sales and other operating revenue”. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also enters into currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 2020 and 2019, or results of operations for the years ended 2020, 2019 and 2018.

Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity.

The net notional long/(short) position of derivative instruments at December 31, 2020, and December 31, 2019, was as follows:

			December 31,						December 31,
			2020						2019
			(millions)
Crude oil (barrels)			40						57
Petroleum products (barrels)			( 46 )						( 38 )
Natural gas (MMBTUs)			( 500 )						( 165 )

Realized and unrealized gains/(losses) on derivative instruments that were recognized in the Consolidated Statement of Income are included in the following lines on a before-tax basis:

			2020						2019						2018
			(millions of dollars)
Sales and other operating revenue			404						( 412 )						130
Crude oil and product purchases			( 407 )						179						( 120 )
Total			( 3 )						( 233 )						10

At December 31, 2020, long-term debt consisted of $ 41,026 million due in U.S. dollars and $ 6,156 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $ 2,930 million, which matures within one year and is included in current liabilities. The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $ 23 billion of long-term debt during 2020. The amounts of long-term debt, excluding finance lease obligations, maturing in each of the four years after December 31, 2021, in millions of dollars, are: 2022 – $ 3,340 ; 2023 – $ 4,024 ; 2024 – $ 3,968 ; and 2025 – $ 4,672 . At December 31, 2020, the Corporation had no unused long-term lines of credit.

The Corporation may use non-derivative financial instruments, such as its foreign currency-denominated debt, as hedges of its net investments in certain foreign subsidiaries. Under this method, the change in the carrying value of the financial instruments due to foreign exchange fluctuations is reported in accumulated other comprehensive income. As of December 31, 2020, the Corporation has designated its $ 5.5 billion of Euro-denominated long-term debt and related accrued interest as a net investment hedge of its European business. The net investment hedge is deemed to be perfectly effective.

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Summarized long-term debt at year-end 2020 and 2019 are shown in the table below:

			Average Rate (1)						Dec 31, 2020						Dec 31, 2019
									(millions of dollars)
Exxon Mobil Corporation (2)
2.222 % notes due 2021									—						2,500
2.397 % notes due 2022									1,150						1,150
1.902 % notes due 2022									750						750
Floating-rate notes due 2022 (Issued 2015)			1.118 %						500						500
Floating-rate notes due 2022 (Issued 2019)			1.189 %						750						750
1.571 % notes due 2023									2,750						—
2.726 % notes due 2023									1,250						1,250
3.176 % notes due 2024									1,000						1,000
2.019 % notes due 2024									1,000						1,000
2.709 % notes due 2025									1,750						1,750
2.992 % notes due 2025									2,807						—
3.043 % notes due 2026									2,500						2,500
2.275 % notes due 2026									1,000						1,000
3.294 % notes due 2027									1,000						—
2.440 % notes due 2029									1,250						1,250
3.482 % notes due 2030									2,000						—
2.610 % notes due 2030									2,000						—
2.995 % notes due 2039									750						750
4.227 % notes due 2040									2,091						—
3.567 % notes due 2045									1,000						1,000
4.114 % notes due 2046									2,500						2,500
3.095 % notes due 2049									1,500						1,500
4.327 % notes due 2050									2,750						—
3.452 % notes due 2051									2,750						—
Exxon Mobil Corporation - Euro-denominated
0.142 % notes due 2024									1,841						—
0.524 % notes due 2028									1,227						—
0.835 % notes due 2032									1,227						—
1.408 % notes due 2039									1,227						—
XTO Energy Inc. (3)
6.100 % senior notes due 2036									192						193
6.750 % senior notes due 2037									294						296
6.375 % senior notes due 2038									227						229
Mobil Corporation
8.625 % debentures due 2021									—						250
Industrial revenue bonds due 2022-2051			0.437 %						2,461						2,461
Other U.S. dollar obligations									78						89
Other foreign currency obligations									61						64
Finance lease obligations			8.730 %						1,680						1,670
Debt issuance costs									( 131 )						( 60 )
Total long-term debt									47,182						26,342

(1) Average effective interest rate for debt and average imputed interest rate for finance leases at December 31, 2020.

(2) Includes premiums of $ 148 million in 2020.

(3) Includes premiums of $ 87 million in 2020 and $ 92 million in 2019.

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The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock, and other forms of awards. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited, expire, or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2020, remaining shares available for award under the 2003 Incentive Program were 71 million.

Restricted Stock and Restricted Stock Units. Awards totaling 8,681 thousand, 8,936 thousand, and 8,771 thousand of restricted (nonvested) common stock units were granted in 2020, 2019, and 2018, respectively. Compensation expense for these awards is based on the price of the stock at the date of grant and is recognized in income over the requisite service period. Shares for these awards are issued to employees from treasury stock. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period . During the applicable restricted periods, the shares and units may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares and units in each award vesting after three years and the remaining 50 percent vesting after seven years . Awards granted to a small number of senior executives have vesting periods of five years for 50 percent of the award and of 10 years for the remaining 50 percent of the award, except that for awards granted prior to 2020 the vesting of the 10 -year portion of the award is delayed until retirement if later than 10 years.

The Corporation has purchased shares in the open market and through negotiated transactions to offset shares or units settled in shares issued in conjunction with benefit plans and programs. The Corporation suspended its first quarter 2021 anti-dilutive share repurchase program due to current market uncertainty and intends to resume this program in the future as market conditions improve.

The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2020.

			2020
Restricted stock and units outstanding			Shares						Weighted Average Grant-Date Fair Value per Share
			(thousands)						(dollars)
Issued and outstanding at January 1			39,628						84.50
Awards issued in 2020			9,030						68.95
Vested			( 8,990 )						86.84
Forfeited			( 83 )						82.04
Issued and outstanding at December 31			39,585						80.43

Value of restricted stock units			2020						2019						2018
Grant price (dollars)			41.15						68.77						77.66
Value at date of grant:			(millions of dollars)
Units settled in stock			325						559						620
Units settled in cash			32						55						61
Total value			357						614						681

As of December 31, 2020, there was $ 1,356 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.2 years. The compensation cost charged against income for the restricted stock and restricted stock units was $ 672 million, $ 741 million, and $ 774 million for 2020, 2019, and 2018, respectively. The income tax benefit recognized in income related to this compensation expense was $ 51 million, $ 51 million, and $ 42 million for the same periods, respectively. The fair value of shares and units vested in 2020, 2019, and 2018 was $ 367 million, $ 647 million, and $ 722 million, respectively. Cash payments of $ 34 million, $ 56 million, and $ 61 million for vested restricted stock units settled in cash were made in 2020, 2019, and 2018, respectively.

---

Litigation. A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our contingency disclosures, “significant” includes material matters, as well as other matters, which management believes should be disclosed. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole.

Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2020, for guarantees relating to notes, loans and performance under contracts. Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure.

			December 31, 2020
			Equity Company Obligations (1)						Other Third-Party Obligations						Total
			(millions of dollars)
Guarantees
Debt-related			986						124						1,110
Other			745						4,944						5,689
Total			1,731						5,068						6,799

(1) ExxonMobil share.

Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition.

In accordance with a Venezuelan nationalization decree issued in February 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” and an increase in PdVSA’s or one of its affiliate’s ownership interest in the Project. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.

ExxonMobil collected awards of $ 908 million in an arbitration against PdVSA under the rules of the International Chamber of Commerce in respect of an indemnity related to the Cerro Negro Project and $ 260 million in an arbitration for compensation due for the La Ceiba Project and for export curtailments at the Cerro Negro Project under rules of International Centre for Settlement of Investment Disputes (ICSID). An ICSID arbitration award relating to the Cerro Negro Project’s expropriation ($ 1.4 billion) was annulled based on a determination that a prior Tribunal failed to adequately explain why the cap on damages in the indemnity owed by PdVSA did not affect or limit the amount owed for the expropriation of the Cerro Negro Project. ExxonMobil filed a new claim seeking to restore the original award of damages for the Cerro Negro Project with ICSID on September 26, 2018.

The net impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition.

---

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The benefit obligations and plan assets associated with the Corporation’s principal benefit plans are measured on December 31.

			Pension Benefits																								Other Postretirement
			U.S.												Non-U.S.												Benefits
			2020						2019						2020						2019						2020						2019
			(percent)
Weighted-average assumptions used to determine benefit obligations at December 31
Discount rate			2.80						3.50						1.60						2.30						2.80						3.50
Long-term rate of compensation increase			5.50						5.75						4.20						4.80						5.50						5.75
			(millions of dollars)
Change in benefit obligation
Benefit obligation at January 1			20,959						18,174						29,918						25,378						8,113						7,471
Service cost			965						757						707						551						181						139
Interest cost			708						766						657						763						277						315
Actuarial loss/(gain) (1)			1,287						2,562						2,344						3,703						( 66 )						556
Benefits paid (2) (3)			( 1,987 )						( 1,300 )						( 1,317 )						( 1,196 )						( 510 )						( 517 )
Foreign exchange rate changes			—						—						1,375						391						23						25
Amendments, divestments and other			( 270 )						—						( 58 )						328						117						124
Benefit obligation at December 31			21,662						20,959						33,626						29,918						8,135						8,113
Accumulated benefit obligation at December 31			17,502						16,387						30,952						27,236						—						—

(1) Actuarial loss/(gain) primarily reflects changes in discount rates, partially offset by lower long-term rates of compensation.

(2) Benefit payments for funded and unfunded plans.

(3) For 2020 and 2019, other postretirement benefits paid are net of $ 16 million and $ 20 million of Medicare subsidy receipts, respectively.

For selection of the discount rate for U.S. plans, several sources of information are considered, including interest rate market indicators and the effective discount rate determined by use of a yield curve based on high-quality, noncallable bonds applied to the estimated cash outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using a spot yield curve of high-quality, local-currency-denominated bonds at an average maturity approximating that of the liabilities.

The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.5 percent in 2022 and subsequent years.

			Pension Benefits																								Other Postretirement
			U.S.												Non-U.S.												Benefits
			2020						2019						2020						2019						2020						2019
			(millions of dollars)
Change in plan assets
Fair value at January 1			13,636						11,134						22,916						19,486						425						386
Actual return on plan assets			2,269						2,521						2,795						3,210						42						54
Foreign exchange rate changes			—						—						1,011						513						—						—
Company contribution			1,004						1,022						597						602						37						41
Benefits paid (1)			( 1,609 )						( 1,041 )						( 992 )						( 883 )						( 58 )						( 56 )
Other			—						—						( 111 )						( 12 )						—						—
Fair value at December 31			15,300						13,636						26,216						22,916						446						425

(1) Benefit payments for funded plans.

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The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local applicable tax rules and regulatory practices do not encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.

			Pension Benefits
			U.S.												Non-U.S.
			2020						2019						2020						2019
			(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans			( 4,156 )						( 4,656 )						( 1,223 )						( 1,728 )
Unfunded plans			( 2,206 )						( 2,667 )						( 6,187 )						( 5,274 )
Total			( 6,362 )						( 7,323 )						( 7,410 )						( 7,002 )

The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.

			Pension Benefits																								Other Postretirement Benefits
			U.S.												Non-U.S.
			2020						2019						2020						2019						2020						2019
			(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31 (1)			( 6,362 )						( 7,323 )						( 7,410 )						( 7,002 )						( 7,689 )						( 7,688 )
Amounts recorded in the consolidated balance sheet consist of:
Other assets			—						—						1,931						1,151						—						—
Current liabilities			( 377 )						( 242 )						( 273 )						( 267 )						( 327 )						( 351 )
Postretirement benefits reserves			( 5,985 )						( 7,081 )						( 9,068 )						( 7,886 )						( 7,362 )						( 7,337 )
Total recorded			( 6,362 )						( 7,323 )						( 7,410 )						( 7,002 )						( 7,689 )						( 7,688 )
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain)			3,102						3,971						5,904						5,662						1,164						1,339
Prior service cost			( 275 )						1						208						360						( 274 )						( 315 )
Total recorded in accumulated other comprehensive income			2,827						3,972						6,112						6,022						890						1,024

(1) Fair value of assets less benefit obligation shown on the preceding page.

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The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class.

			Pension Benefits																																				Other Postretirement Benefits
			U.S.																		Non-U.S.
			2020						2019						2018						2020						2019						2018						2020						2019						2018
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31			(percent)
Discount rate			3.50						4.40						3.80						2.30						3.00						2.80						3.50						4.40						3.80
Long-term rate of return on funded assets			5.30						5.30						6.00						4.10						4.10						4.70						4.60						4.60						6.00
Long-term rate of compensation increase			5.75						5.75						5.75						4.80						4.30						4.30						5.75						5.75						5.75
Components of net periodic benefit cost			(millions of dollars)
Service cost			965						757						819						707						551						608						181						139						152
Interest cost			708						766						721						657						763						754						277						315						301
Expected return on plan assets			( 703 )						( 568 )						( 727 )						( 897 )						( 777 )						( 951 )						( 18 )						( 15 )						( 23 )
Amortization of actuarial loss/(gain)			310						305						362						416						306						409						95						55						116
Amortization of prior service cost			5						5						5						68						56						46						( 42 )						( 42 )						( 40 )
Net pension enhancement and curtailment/settlement cost			280						164						268						49						( 98 )						44						—						—						—
Net periodic benefit cost			1,565						1,429						1,448						1,000						801						910						493						452						506
Changes in amounts recorded in accumulated other comprehensive income:
Net actuarial loss/(gain)			( 279 )						609						479						446						1,268						( 66 )						( 92 )						517						( 594 )
Amortization of actuarial (loss)/gain			( 590 )						( 469 )						( 630 )						( 442 )						( 208 )						( 453 )						( 95 )						( 55 )						( 116 )
Prior service cost/(credit)			( 271 )						—						—						( 82 )						379						98						—						—						—
Amortization of prior service (cost)/credit			( 5 )						( 5 )						( 5 )						( 68 )						( 56 )						( 46 )						42						42						40
Foreign exchange rate changes			—						—						—						236						19						( 356 )						11						—						( 8 )
Total recorded in other comprehensive income			( 1,145 )						135						( 156 )						90						1,402						( 823 )						( 134 )						504						( 678 )
Total recorded in net periodic benefit cost and other comprehensive income, before tax			420						1,564						1,292						1,090						2,203						87						359						956						( 172 )

Costs for defined contribution plans were $ 358 million, $ 422 million and $ 391 million in 2020, 2019 and 2018, respectively.

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A summary of the change in accumulated other comprehensive income is shown in the table below:

			Total Pension and Other Postretirement Benefits
			2020						2019						2018
			(millions of dollars)
(Charge)/credit to other comprehensive income, before tax
U.S. pension			1,145						( 135 )						156
Non-U.S. pension			( 90 )						( 1,402 )						823
Other postretirement benefits			134						( 504 )						678
Total (charge)/credit to other comprehensive income, before tax			1,189						( 2,041 )						1,657
(Charge)/credit to income tax (see Note 4)			( 153 )						550						( 470 )
(Charge)/credit to investment in equity companies			( 110 )						( 19 )						24
(Charge)/credit to other comprehensive income including noncontrolling interests, after tax			926						( 1,510 )						1,211
Charge/(credit) to equity of noncontrolling interests			30						146						( 114 )
(Charge)/credit to other comprehensive income attributable to ExxonMobil			956						( 1,364 )						1,097

The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in plan assets and liabilities and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive global equity and local currency fixed income index funds to diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed income funds are largely invested in investment grade corporate and government debt securities.

Studies are periodically conducted to establish the preferred target asset allocation percentages. The target asset allocation for the U.S. benefit plans and the major non-U.S. plans is 30 percent equity securities and 70 percent debt securities. The equity for the U.S. and certain non-U.S. plans include a small allocation to private equity partnerships that primarily focus on early-stage venture capital of 4 percent and 2 percent, respectively.

The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.

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The 2020 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:

			U.S. Pension																																	Non- U.S. Pension
			Fair Value Measurement at December 31, 2020, Using:																																	Fair Value Measurement at December 31, 2020, Using:
			Level 1						Level 2									Level 3						Net Asset Value						Total						Level 1									Level 2									Level 3						Net Asset Value						Total
			(millions of dollars)
Asset category:
Equity securities
U.S.			—						—									—						2,323						2,323						—									—									—						4,177						4,177
Non-U.S.			—						—									—						1,703						1,703						89			(1)						—									—						3,285						3,374
Private equity			—						—									—						548						548						—									—									—						530						530
Debt securities
Corporate			—						5,146			(2)						—						1						5,147						—									138			(2)						—						5,212						5,350
Government			—						5,261			(2)						—						2						5,263						250			(3)						116			(2)						—						11,993						12,359
Asset-backed			—						—									—						1						1						—									24			(2)						—						239						263
Cash			—						—									—						308						308						69									21			(4)						—						50						140
Total at fair value			—						10,407									—						4,886						15,293						408									299									—						25,486						26,193
Insurance contracts at contract value																														7																																				23
Total plan assets																														15,300																																				26,216

(1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.

(4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.

			Other Postretirement
			Fair Value Measurement at December 31, 2020, Using:
			Level 1						Level 2									Level 3						Net Asset Value						Total
			(millions of dollars)
Asset category:
Equity securities
U.S.			88			(1)			—									—						—						88
Non-U.S.			48			(1)			—									—						—						48
Debt securities
Corporate			—						103			(2)						—						—						103
Government			—						204			(2)						—						—						204
Asset-backed			—						—									—						—						—
Cash			—						—									—						3						3
Total at fair value			136						307									—						3						446

(1) For equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

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The 2019 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:

			U.S. Pension																														Non-U.S. Pension
			Fair Value Measurement at December 31, 2019, Using:																														Fair Value Measurement at December 31, 2019, Using:
			Level 1						Level 2									Level 3						Net Asset Value						Total						Level 1									Level 2									Level 3						Net Asset Value						Total
			(millions of dollars)
Asset category:
Equity securities
U.S.			—						—									—						1,960						1,960						—									—									—						3,436						3,436
Non-U.S.			—						—									—						1,656						1,656						70			(1)						—									—						3,015						3,085
Private equity			—						—									—						499						499						—									—									—						489						489
Debt securities
Corporate			—						4,932			(2)						—						1						4,933						—									129			(2)						—						4,486						4,615
Government			—						4,470			(2)						—						2						4,472						280			(3)						139			(2)						—						10,511						10,930
Asset-backed			—						—									—						1						1						—									21			(2)						—						212						233
Cash			—						—									—						107						107						33									12			(4)						—						61						106
Total at fair value			—						9,402									—						4,226						13,628						383									301									—						22,210						22,894
Insurance contracts at contract value																														8																																				22
Total plan assets																														13,636																																				22,916

(1) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

(2) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(3) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.

(4) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.

			Other Postretirement
			Fair Value Measurement at December 31, 2019, Using:
			Level 1						Level 2									Level 3						Net Asset Value						Total
			(millions of dollars)
Asset category:
Equity securities
U.S.			—						—									—						81						81
Non-U.S.			—						—									—						49						49
Debt securities
Corporate			—						92			(1)						—						—						92
Government			—						200			(1)						—						—						200
Asset-backed			—						—									—						—						—
Cash			—						—									—						3						3
Total at fair value			—						292									—						133						425

(1) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

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A summary of pension plans with an accumulated benefit obligation and projected benefit obligation in excess of plan assets is shown in the table below:

			Pension Benefits
			U.S.												Non-U.S.
			2020						2019						2020						2019
			(millions of dollars)
For funded pension plans with an accumulated benefit obligation
in excess of plan assets:
Accumulated benefit obligation			16,129						14,940						4,602						3,026
Fair value of plan assets			15,300						13,636						2,652						1,381
For funded pension plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation			19,456						18,292						13,836						12,496
Fair value of plan assets			15,300						13,636						10,681						9,616
For unfunded pension plans:
Projected benefit obligation			2,206						2,667						6,187						5,274
Accumulated benefit obligation			1,373						1,447						5,469						4,629

All other postretirement benefit plans are unfunded or underfunded.

			Pension Benefits												Other Postretirement Benefits
			U.S.						Non-U.S.						Gross						Medicare Subsidy Receipt
			(millions of dollars)
Contributions expected in 2021			865						395						—						—
Benefit payments expected in:
2021			2,434						1,310						424						22
2022			1,079						1,193						426						23
2023			1,105						1,214						420						25
2024			1,124						1,240						418						26
2025			1,142						1,186						415						27
2026 - 2030			5,971						6,274						2,058						143

The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment is organized and operates to manufacture and sell petroleum products. The Chemical segment is organized and operates to manufacture and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries.

These functions have been defined as the operating segments of the Corporation because they are the segments (1) that engage in business activities from which revenues are recognized and expenses are incurred; (2) whose operating results are regularly reviewed by the Corporation’s chief operating decision maker to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available.

Earnings after income tax include transfers at estimated market prices.

In the Corporate and financing segment, interest revenue relates to interest earned on cash deposits and marketable securities. Interest expense includes non-debt-related interest expense of $ 148 million in 2020, $ 105 million in 2019 and $ 84 million in 2018.

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Geographic

Sales and other operating revenue			2020						2019						2018
			(millions of dollars)
United States			62,663						89,612						96,930
Non-U.S.			115,911						165,971						182,402
Total			178,574						255,583						279,332
Significant non-U.S. revenue sources include: (1)
Canada			13,093						19,735						22,672
United Kingdom			11,055						17,479						18,702
Singapore			9,442						12,128						13,689
France			8,676						12,740						13,637
Italy			7,091						10,459						13,396
Belgium			6,231						11,644						15,664
Australia			5,839						7,941						8,780

(1) Revenue is determined by primary country of operations. Excludes certain sales and other operating revenues in Non-U.S. operations where attribution to a specific country is not practicable.

			December 31,
Long-lived assets			2020						2019						2018
			(millions of dollars)
United States			94,732						114,372						108,147
Non-U.S.			132,821						138,646						138,954
Total			227,553						253,018						247,101
Significant non-U.S. long-lived assets include:
Canada			36,232						39,130						37,433
Australia			14,792						13,933						14,548
Singapore			12,129						11,645						11,148
Kazakhstan			8,882						9,315						9,726
Papua New Guinea			7,803						8,057						8,269
Nigeria			6,345						7,640						8,421
United Arab Emirates			5,381						5,262						4,859
Russia			4,616						5,135						5,456
Angola			4,405						5,784						7,021

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			2020																		2019																		2018
			U.S.						Non-U.S.						Total						U.S.						Non-U.S.						Total						U.S.						Non-U.S.						Total
																					(millions of dollars)
Income tax expense (benefit)
Federal and non-U.S.
Current			262						2,908						3,170						( 121 )						6,171						6,050						459						9,001						9,460
Deferred - net			( 6,045 )						( 2,007 )						( 8,052 )						( 255 )						( 420 )						( 675 )						518						( 614 )						( 96 )
U.S. tax on non-U.S. operations			13						—						13						89						—						89						42						—						42
Total federal and non-U.S.			( 5,770 )						901						( 4,869 )						( 287 )						5,751						5,464						1,019						8,387						9,406
State			( 763 )						—						( 763 )						( 182 )						—						( 182 )						126						—						126
Total income tax expense (benefit)			( 6,533 )						901						( 5,632 )						( 469 )						5,751						5,282						1,145						8,387						9,532
All other taxes and duties
Other taxes and duties			3,108						23,014						26,122						3,566						26,959						30,525						3,498						29,165						32,663
Included in production and manufacturing expenses			1,148						663						1,811						1,385						811						2,196						1,245						857						2,102
Included in SG&A expenses			164						328						492						160						305						465						153						312						465
Total other taxes and duties			4,420						24,005						28,425						5,111						28,075						33,186						4,896						30,334						35,230
Total			( 2,113 )						24,906						22,793						4,642						33,826						38,468						6,041						38,721						44,762

The above provisions for deferred income taxes include net benefits of $ 25 million in 2020, $ 740 million in 2019, and $ 289 million in 2018 related to changes in tax laws and rates, and a benefit of $ 6.3 billion in 2020 related to asset impairments.

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The reconciliation between income tax expense (credit) and a theoretical U.S. tax computed by applying a rate of 21 percent for 2020, 2019 and 2018 is as follows:

			2020						2019						2018
			(millions of dollars)
Income (Loss) before income taxes
United States			( 27,704 )						( 53 )						5,200
Non-U.S.			( 1,179 )						20,109						25,753
Total			( 28,883 )						20,056						30,953
Theoretical tax			( 6,065 )						4,212						6,500
Effect of equity method of accounting			( 364 )						( 1,143 )						( 1,545 )
Non-U.S. taxes in excess of/(less than) theoretical U.S. tax (1)(2)			1,606						2,573						4,626
State taxes, net of federal tax benefit (1)			( 603 )						( 144 )						100
Enactment-date effects of U.S. tax reform			—						—						( 291 )
Other			( 206 )						( 216 )						142
Total income tax expense (credit)			( 5,632 )						5,282						9,532
Effective tax rate calculation
Income tax expense (credit)			( 5,632 )						5,282						9,532
ExxonMobil share of equity company income taxes			861						2,490						3,142
Total income tax expense (credit)			( 4,771 )						7,772						12,674
Net income (loss) including noncontrolling interests			( 23,251 )						14,774						21,421
Total income (loss) before taxes			( 28,022 )						22,546						34,095
Effective income tax rate			17		%				34		%				37		%

(1) 2020 includes the impact of an increase in valuation allowance of $ 647 million in non-U.S. and $ 115 million in U.S. state jurisdictions.

(2) 2019 includes taxes less than the theoretical U.S. tax of $ 773 million from Norway operations and the sale of upstream assets, $ 657 million from a tax rate change in Alberta, Canada, and $ 268 million from an adjustment to a prior year tax position.

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Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

Deferred tax liabilities/(assets) are comprised of the following at December 31:

Tax effects of temporary differences for:			2020						2019
			(millions of dollars)
Property, plant and equipment			28,778						36,029
Other liabilities			6,427						7,653
Total deferred tax liabilities			35,205						43,682
Pension and other postretirement benefits			( 4,703 )						( 4,712 )
Asset retirement obligations			( 3,150 )						( 3,403 )
Tax loss carryforwards			( 8,982 )						( 7,404 )
Other assets			( 7,095 )						( 7,735 )
Total deferred tax assets			( 23,930 )						( 23,254 )
Asset valuation allowances			2,731						1,924
Net deferred tax liabilities			14,006						22,352

In 2020, asset valuation allowances of $ 2,731 million increased by $ 807 million and included net provisions of $ 762 million and foreign currency effects of $ 41 million.

Balance sheet classification			2020						2019
			(millions of dollars)
Other assets, including intangibles, net			( 4,159 )						( 3,268 )
Deferred income tax liabilities			18,165						25,620
Net deferred tax liabilities			14,006						22,352

The Corporation’s undistributed earnings from subsidiary companies outside the United States include amounts that have been retained to fund prior and future capital project expenditures. Deferred income taxes have not been recorded for potential future tax obligations, such as foreign withholding tax and state tax, as these undistributed earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2020, it is not practicable to estimate the unrecognized deferred tax liability. However, unrecognized deferred taxes on remittance of these funds are not expected to be material.

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Unrecognized Tax Benefits. The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. The following table summarizes the movement in unrecognized tax benefits:

Gross unrecognized tax benefits			2020						2019						2018
			(millions of dollars)
Balance at January 1			8,844						9,174						8,783
Additions based on current year's tax positions			253						287						375
Additions for prior years' tax positions			218						120						240
Reductions for prior years' tax positions			( 201 )						( 97 )						( 125 )
Reductions due to lapse of the statute of limitations			( 237 )						( 279 )						( 5 )
Settlements with tax authorities			( 113 )						( 538 )						( 68 )
Foreign exchange effects/other			—						177						( 26 )
Balance at December 31			8,764						8,844						9,174

The gross unrecognized tax benefit balances shown above are predominantly related to tax positions that would reduce the Corporation’s effective tax rate if the positions are favorably resolved. Unfavorable resolution of these tax positions generally would not increase the effective tax rate. The 2020, 2019 and 2018 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income.

Resolution of these tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the Corporation. In the United States, the Corporation has various ongoing U.S. federal income tax positions at issue with the Internal Revenue Service (IRS) for tax years beginning in 2006. The Corporation filed a refund suit for tax years 2006-2009 in U.S. federal district court (District Court) with respect to the positions at issue for those years. These positions are reflected in the unrecognized tax benefits table above. On February 24, 2020, the Corporation received an adverse ruling on this suit. The IRS has asserted penalties associated with several of those positions. The Corporation has not recognized the penalties as an expense because the Corporation does not expect the penalties to be sustained under applicable law. On January 13, 2021, the District Court ruled that no penalties apply to the Corporation's positions in this suit. Proceedings in the District Court are continuing. Unfavorable resolution of all positions at issue with the IRS would not have a material adverse effect on the Corporation’s operations or financial condition.

It is reasonably possible that the total amount of unrecognized tax benefits could increase or decrease by 10 percent in the next 12 months.

The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:

Country of Operation			Open Tax Years
Abu Dhabi			2018			—			2020
Angola			2018			—			2020
Australia			2010			—			2020
Belgium			2017			—			2020
Canada			2001			—			2020
Equatorial Guinea			2007			—			2020
Indonesia			2007			—			2020
Iraq			2015			—			2020
Malaysia			2011			—			2020
Nigeria			2006			—			2020
Norway			2010			—			2020
Papua New Guinea			2008			—			2020
Russia			2018			—			2020
United Kingdom			2015			—			2020
United States			2006			—			2020

The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.

For 2020, the Corporation's net interest expense was a credit of $ 6 million on income tax reserves. The Corporation incurred $ 0 million and $ 3 million in interest expense on income tax reserves in 2019 and 2018, respectively. The related interest payable balances were $ 61 million and $ 71 million at December 31, 2020, and 2019, respectively.

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During 2020, ExxonMobil conducted an extensive global review of staffing levels and subsequently commenced targeted workforce reductions within a number of countries to improve efficiency and reduce costs. The programs, which are expected to be substantially completed by the end of 2021, include both voluntary and involuntary employee separations and reductions in contractors.

In 2020 the Corporation recorded before-tax charges of $ 450 million, consisting primarily of employee separation costs, associated with announced workforce reduction programs in Europe, North America, and Australia. These costs are captured in “Selling, general and administrative expenses” on the Statement of Income and reported in the Corporate and financing segment. The Corporation estimates additional charges of up to $ 200 million in 2021 related to planned workforce reduction programs.

The following table summarizes the reserves and charges related to the workforce reduction programs, which are recorded in “Accounts payable and accrued liabilities.”

			2020
			(millions of dollars)
Balance at January 1			—
Additions/adjustments			450
Payments made			( 47 )
Balance at December 31			403

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